Method of operating a drilling system

ABSTRACT

A method of operating a drilling system for drilling a subterranean bore hole. The drilling system includes a drill string which rotates during a drilling, and a sealing device which provides a substantially fluid tight seal around the drill string while the drill string is rotating during the drilling. The method includes injecting a fluid into an annular volume around the drill string directly above the sealing device, and controlling a first fluid pressure in the annular volume around the drill string above the sealing device so that the first fluid pressure is greater than a second fluid pressure in the annular volume around the drill string directly below the sealing device.

CROSS REFERENCE TO PRIOR APPLICATIONS

This application is a U.S. National Phase application under 35 U.S.C.§371 of International Application No. PCT/GB2015/051144, filed on Apr.15, 2015 and which claims benefit to Great Britain Patent ApplicationNo. 1407072.6, filed on Apr. 22, 2014. The International Application waspublished in English on Oct. 29, 2015 as WO 2015/162410 A1 under PCTArticle 21(2).

FIELD

The present invention relates to an improved method of operating adrilling system for drilling a subsea or subterranean well bore for oiland/or gas production.

BACKGROUND

Subterranean drilling typically involves rotating a drill bit fromsurface or on a downhole motor at the remote end of a tubular drillstring. It involves pumping a fluid down the inside of the tubular drillstring, through the drill bit, and circulating this fluid continuouslyback to surface via the drilled space between the hole/tubular, referredto as the annulus. For a subsea well bore, a tubular, known as a riserextends from the rig to the top of the wellbore which exists at subsealevel on the ocean floor. It provides a continuous pathway for the drillstring and the fluids emanating from the well bore. In effect, the riserextends the wellbore from the sea bed to the rig, and the annulus alsocomprises the annular space between the outer diameter of the drillstring and the riser.

As drilling progresses pipe has to be connected to the existingdrillstring to drill deeper. Conventionally, this involves shutting downfluid circulation completely so the pipe can be connected into place asthe top drive has to be disengaged.

The large diameter sections that exist at the end of each section ofdrillpipe are referred to as tool joints. During a connection, theseareas provide a low stress area where the rig pipe tongs or IronRoughneck can be placed to grip the pipe and apply torque to either makeor break a connection.

Conventionally, the well bore is open to atmospheric pressure and thereis no surface applied pressure or other pressure existing in the system.The drillpipe rotates freely without any sealing elements imposed oracting on the drill pipe at the surface, and there is no requirement todivert the return fluid flow or exert pressure on the system duringthese standard operations.

Managed pressure drilling and/or underbalanced drilling utilizesadditional special equipment that has been developed to keep the wellclosed at all times, and the wellhead pressures in these cases arenon-atmospheric as in the traditional art of the conventionaloverbalanced drilling method. In such drilling systems, drilling fluidis circulated within a closed loop system. The closed loop is generatedby a seal around the drillpipe at surface or subsea using a pressurecontainment device, diverting all returned flow from the wellboreannulus to a flow line connected to the annulus below the sealing point.The function of the pressure containment device is to allow the drillstring and its tool joints to pass through with reciprocation/strippingor rotation with wellbore pressure below while maintaining the sealintegrity.

With drilling activity in progress and the device closed a back pressureis created on the annulus. The drill string is stripped or rotatedthrough the sealing element(s) pressure containment device whichisolates the pressurized annulus from the external atmosphere whilemaintaining a pressure seal around the drillpipe. A typical sealingelement in existing pressure containment designs includes an elastomeror rubber packing/sealing element and a bearing assembly that allows thesealing element to rotate along with the drillstring. There is norotational movement between the drillstring and the sealing element, andonly the bearing assembly exhibits the rotational movement duringdrilling. Rotating pressure containment devices are well known in theart of pressurized drilling, referred to as Rotating Control Head (RCD),Rotating Blow Out Preventer (RBOP), or Pressure Control While Drilling(PCWD), and are described in detail in patents U.S. Pat. No.7,699,109B2, U.S. Pat. No. 7,926,560, and U.S. Pat. No. 6,129,152.

Drillpipe rotation and vertical movement wears out the sealing elements,and the passage of tool joints and larger OD tubulars causes the sealingelement to expand and contract multiple times with the diametricalchanges in the drill string. With wellbore pressure present below thesealing element and atmospheric or near atmospheric pressure above, alarge differential pressure is produced across the sealing face, withthe highest magnitude of differential pressure existing in the bottomsealing area of the element where it contacts the tubular. As a result,the lower sealing area between the tubular and the element generallyexhibits the highest wear rate, and as the pressure differentialdecreases closer to the top of the sealing element so does the degree ofwear within the sealing face. Therefore, a higher wellbore pressurebelow the sealing point creates a higher differential pressure acrossthe sealing face, and ultimately, higher wear rates in the lower area ofthe element result.

Typically, in the prior art, a dual sealing arrangement for an RCD orother rotating pressure control device is a common configuration usedfor pressurized drilling. The operational history of the dual sealingarrangement for any rotating pressure control device reveals that thelower sealing element is consistently the first failure mechanism forthe assembly because of the magnitude of the differential pressureacross the lowest element. The pressure between the elements iscontinuously monitored with these systems, and when the pressure startsto increase this is a positive indicator that the lower sealing elementis, or has, failed.

Furthermore, the frictional coefficients existing between the steeltubulars and the elastomeric sealing material of the rotating pressurecontrol devices are quite high resulting in a high wear rate occurringwithin the sealing face. Most designs on the market to date lack thecapability to lubricate or self-lubricate the sealing face between theelement and the tubular. During drilling and tripping under pressure,the degree of heat generated from the friction between the tubular andthe element through the vertical movement and rotational motion of thetubular within the element is substantial without a friction reducingfluid to lubricate and cool the sealing interface. Thus, the wear ratesfor conventional sealing devices increases drastically in addition tothe effects of differential pressure.

An alternative apparatus to the rotating control device technology,utilizing a non-rotating sealing device is described in patentapplications WO2012127227 and WO2011128690. This device eliminates therequirement for a bearing assembly, and includes a single or dual sealsleeve assembly installed within a specified housing within the risersystem and secured in place with hydraulically locking dogs/pistons.Rotation of the seal sleeve assembly with the drill pipe is preventedthrough the frictional forces of an adjacent annular packer assemblywithin the housing which applies pressure to the external surface of theseal sleeve when it is in position in the housing. The seal sleeve'smechanical structure and composite materials result in a high wearresistant low friction coefficient sealing face on the drill pipe. Thissystem does not use the conventional bearing systems described in theprior art.

In one embodiment described in WO 2011/128690, a lubricating circuit isutilized to circulate a fluid such as water or oil based fluids betweentwo sealing elements of an annular stripping sleeve, or alternatelyreferred to as a seal sleeve assembly, with the intent of providing aconstant fluid pressure between the two seals. The fluid is metered inand out of the annular volume between the sealing elements to accountfor any fluid loss within the circulating system and any gain throughthe ingress of wellbore fluids. Maintaining a constant fluid pressurebetween the sealing elements decreases the pressure differential acrossthe assembly and enhances the longevity of the sealing assembly. Withthis circuit, a negative differential pressure is created across thelower sealing element utilizing circulation pressure through thisannular volume. For example, if the wellbore pressure below the lowestelement is 1,000 psi, the circuit volume is pressurized to 500 psi. Themagnitude of the differential across the sealing assembly is decreased,and a negative differential of 500 psi would result across the lowersealing element.

The circuit described in patent applications WO 2012/127227 and WO2011/128690 is now referred to as the Seal Integrity Circuit (SIC), andthe inventive system and method introduces further aspects of such asystem which may enhance the efficiency and safety of its operation.

SUMMARY

In an embodiment, the present invention provides a method of operating adrilling system for drilling a subterranean bore hole. The drillingsystem includes a drill string configured to rotate during a drilling,and a sealing device configured to provide a substantially fluid tightseal around the drill string while the drill string is rotating duringthe drilling. The method includes injecting a fluid into an annularvolume around the drill string directly above the sealing device, andcontrolling a first fluid pressure in the annular volume around thedrill string above the sealing device so that the first fluid pressureis greater than a second fluid pressure in the annular volume around thedrill string directly below the sealing device.

BRIEF DESCRIPTION OF THE DRAWINGS

The present invention is described in greater detail below on the basisof embodiments and of the drawings in which:

FIG. 1 shows a schematic illustration of a drilling system according toa first aspect of the present invention; and

FIG. 2 shows a flow chart illustrating a method of using the drillingsystem shown in FIG. 1, and according to a second aspect of the presentinvention.

DETAILED DESCRIPTION

According to a first aspect of the present invention, a method ofoperating a drilling system for drilling a subterranean bore hole isprovided, the drilling system including a drill string and a sealingdevice which is operable to provide a substantially fluid tight sealaround the drill string whilst the drill string is rotating duringdrilling, wherein the method includes the steps of:

-   -   a) injecting fluid into the annular volume around the drill        string directly above the sealing device, and    -   b) controlling the fluid pressure in the annular volume around        the drill string above the sealing device so that this pressure        is greater than the fluid pressure in the annular volume around        the drill string directly below the lowermost sealing device.

In an embodiment of the present invention, the drilling system can, forexample, include two sealing devices which are operable to provide asubstantially fluid tight seal around the drill string whilst the drillstring is rotating during drilling, and the method includes the stepsof:

-   -   a) injecting fluid into the annular volume around the drill        string between the two sealing devices, and    -   b) controlling the fluid pressure in the annular volume around        the drill string between the two sealing devices so that this        pressure is greater than the fluid pressure in the annular        volume around the drill string directly below the lowermost        sealing device.

The fluid pressure in the annular volume around the drill string betweenthe two sealing devices can, for example, also be controlled so thatthis pressure is greater than the fluid pressure in the annular volumearound the drill string directly above the uppermost sealing device.

The drilling system may be provided with an injection line whichconnects the annular volume around the drill string directly above thesealing device, or, where two sealing devices are provided, the annularvolume around the drill string between the two sealing devices, with aninjection pump which is operable to pump fluid from a fluid reservoirinto the annular volume around the drill string directly above thesealing device, or, where two sealing devices are provided, the annularvolume around the drill string between the two sealing devices.

The drilling system may be provided with a return line which connectsthe annular volume around the drill string directly above the sealingdevice, or, where two sealing devices are provided, the annular volumearound the drill string between the two sealing devices, with a fluidreservoir, there being a back pressure valve provided in the returnline, the back pressure valve being adjustable to restrict the flow offluid along the return line to a greater or lesser extent. In this case,the method may further include the step of controlling the fluidpressure in the annular volume around the drill string directly abovethe sealing device, or, where two sealing devices are provided, theannular volume around the drill string between the two sealing devicesby controlling the back pressure valve to vary to the extent to which itrestricts flow of fluid along the return line.

In an embodiment of the present invention, the return line can, forexample, be connected to the same fluid reservoir as the injection pump.

In an embodiment of the present invention, an injection pressure sensorcan, for example, be provided to measure the fluid pressure in theinjection line.

In an embodiment of the present invention, a return pressure sensor can,for example, be provided to measure the fluid pressure in the returnline. In this case, the return pressure sensor can, for example, belocated upstream of the back pressure valve.

The pressure measured by a pressure sensor located in one or both of theinjection line and/or return line may be used in controlling the fluidpressure in the annular volume around the drill string directly abovethe sealing device, or, where two sealing devices are provided, theannular volume around the drill string between the two sealing devices.

In one embodiment, the or each sealing device is configured such thatthe sealing pressure it exerts on the drill string when operated to sealagainst the drill string can be varied. In this case, the method mayfurther include the step of varying the sealing pressure exerted by theor each sealing device on the drill string to establish leakage ofinjected fluid between the sealing device and the drill string at adesired rate. In this case, the method may further include the step ofcontrolling the fluid pressure in the annular volume around the drillstring directly above the sealing device, or, where two sealing devicesare provided, the annular volume around the drill string between the twosealing devices by controlling the sealing pressure of the or eachsealing device.

A flow meter may be provided in the return line upstream of the backpressure valve, and a flow meter may be provided in the injection line.In this case, the method may further include monitoring the inflow rateof flow of fluid into the annular volume around the drill stringdirectly above the sealing device, or, where two sealing devices areprovided, the annular volume around the drill string between the twosealing devices, and the outflow rate of flow of fluid out of theannular volume around the drill string directly above the sealingdevice, or, where two sealing devices are provided, the annular volumearound the drill string between the two sealing devices, comparing theinflow rate and outflow rate, and using this comparison to detect a lossof sealing integrity of the sealing device, or, where two sealingdevices are provided, one or both of the sealing devices.

In an embodiment of the present invention, the injection flow meter andreturn flow meter can, for example, both be mass flow meters, and themethod further includes the step of comparing the inflow rate andoutflow rate, and using this comparison to detect an influx of gas intothe injected fluid.

The drilling system further includes a mud gas separator, and the methodfurther includes directing fluid from the return line to the mud gasseparator is gas is detected in the injected fluid, and returningdegasified liquid from the mud gas separator to the fluid reservoir. Inthis case, the return line can, for example, include a main returns flowline which extends directly to the fluid reservoir and an emergencyreturns flow line which extends to the mud gas separator, and a valveassembly which is operable to control flow of fluid along the mainreturns flow line and emergency returns flow line. In this case, themethod may include the step of operating the valve assembly to close themain returns flow line and open the emergency returns flow line if gasis detected in the injected fluid.

The drilling system may further include a pressure relief system whichis operable to direct fluid from the annular volume around the drillstring directly above the sealing device, or, where two sealing devicesare provided, the annular volume around the drill string between the twosealing devices to the fluid reservoir if the pressure in the annularvolume around the drill string directly above the sealing device, or,where two sealing devices are provided, the annular volume around thedrill string between the two sealing devices exceeds a predeterminedlevel. The pressure relief system may include a pressure relief valvewhich is located in a pressure relief line between the return line andthe fluid reservoir, and is configured to allow flow of fluid along thepressure relief line if the pressure in the annular volume around thedrill string directly above the sealing device, or, where two sealingdevices are provided, the annular volume around the drill string betweenthe two sealing devices exceeds a predetermined level. The pressurerelief line may extend from the pressure relief valve to the fluidreservoir via the mud gas separator.

The drilling systems may be configured to switch off the injection pumpautomatically if the pressure in the annular volume around the drillstring directly above the sealing device, or, where two sealing devicesare provided, the annular volume around the drill string between the twosealing devices, exceeds a predetermined level. In this case, the methodmay further include adjusting the sealing pressure of the or eachsealing device to reduce the pressure in the annular volume around thedrill string directly above the sealing device, or, where two sealingdevices are provided, the annular volume around the drill string betweenthe two sealing devices to below the predetermined level.

The pressure relief system may include a pressure relief valve which islocated in a pressure relief line between the injection line and thefluid reservoir, and is configured to allow flow of fluid along thepressure relief line if the pressure in the annular volume around thedrill string directly above the sealing device, or, where two sealingdevices are provided, the annular volume around the drill string betweenthe two sealing devices exceeds a predetermined level.

The sealing device or one or both of the sealing devices can, forexample, include a tubular seal which is mounted around the drillstring.

The sealing device or one or both of the sealing devices may furtherinclude housing with a main passage, and an actuator which is operableto urge the seal into sealing engagement with the drill string. Theactuator may comprise a piston which is movable generally parallel tothe longitudinal axis of the main passage in the housing. The sealingdevice or one or both of the sealing devices may further include anannular packer which has a central aperture in which the seal ismounted, the actuator being operable to act on the packer so that thepacker pushes the seal into engagement with a drill string extendingalong the main passage of the housing.

According to a second aspect of the present invention we provide atangible computer readable medium having installed thereon instructionswhich when executed by a processing device cause the processing deviceto implement the method according to the first aspect of the presentinvention.

An embodiment of the present invention will now be described, by way ofexample only, with reference to the following figures of which,

Referring now to FIG. 1, there is shown a drilling system 10 includingtwo sealing devices 12 a, 12 b, and a drill string 14, the sealingdevices 12 a, 12 b being operable to seal around drill string 14 tocontain fluid pressure in the annular space around the drill string 14,whilst allowing the drill string 14 to rotate about its longitudinalaxis A.

In this example, the drilling system is an offshore system whichincludes an offshore marine riser 15, with a section of riser 15 a aboveand a section of riser 15 b below the sealing devices 12 a, 12 b. Thedrill string 14 extends from the surface, down the riser 15, through thesealing devices 12 a, 12 b, and into the wellbore below. The annularspace around the drill string 14 below the lowest sealing device 12 bcontains the returned fluid stream from the wellbore being drilled atpressure P_(WB), and may contain fluids, solids, and entrained gas. Theannular space around the drill string 14 above the upper sealing device12 a contains a column of drilling fluid at atmospheric pressure with ahydrostatic pressure P_(HP) acting downwards on the sealing device 12 aat the bottom of the fluid column. The magnitude of P_(HP) is determinedby the mud weight and the setting depth of the sealing devices 12 a, 12b within the riser configuration.

It should be appreciated, however, that the present invention mayequally be employed in a land based drilling system, in which case thesealing devices could be installed on the top of a land based blowoutpreventer (BOP).

Examples of suitable sealing devices are shown in WO2012127227 andWO2011128690, the contents of which are incorporated herein byreference. To summarize, however, each sealing device comprises aflexible tubular sealing element which has a main passage, along which,the drill string extends, so that the sealing element can be urged intosealing engagement with the drill string.

In these embodiments, the sealing device also includes an annular packerwhich is made from an elastomeric material such as rubber, and which ismounted in a tubular housing which encloses a main passage. The sealingelement is located in the central aperture of the annular packer, sothat, in use, the drill string 14 extends along the main passage of thehousing, and through the central aperture in the annular packer. Alsocontained in the housing is an actuator which is operable to act on theannular packer to urge it into engagement with the sealing element, sothat the sealing element is, in turn, forced into sealing engagementwith the drill string 14. In an embodiment, the actuator can, forexample, be a piston which is movable generally parallel to thelongitudinal axis A of the drill string 14. The actuator can, forexample, be fluid pressure operated, for example, the supply ofpressurized fluid to a close chamber provided in the housing causing thepiston to move to force the packer against the housing, thus causing thepacker to constrict, so that the diameter of its central aperturereduces, and to urge the sealing element into sealing engagement withthe drill string 14. The closing pressure applied to the upper and lowersealing elements of the upper and lower sealing devices 12 a, 12 bthrough this fluid pressure control system will be referred P_(RDD1) andP_(RDD2) respectively.

The sealing element can, for example, be retained in the desiredposition within the packer by two sets of locking dogs which are movablebetween a retracted position in which they are contained within thehousing, and an extended position in which they extend from the housinginto its main passage. The locking dogs can, for example, also be fluidpressure operated, and the two sets are spaced along the housing so thatthe sealing element is captured between the two sets when it is in thedesired position, and when the or each locking dog in each set is in itsextended position.

In this case, as mentioned above, two sealing devices 12 a, 12 b areprovided, the sealing devices being spaced along the longitudinal axis Aof the drill string 14. The housings of the two sealing devices 12 a, 12b may be integrated to form a single housing, and the sealing elementsmay be joined end to end to form a dual seal sealing sleeve. In thelatter case, there is no need to provide two sets of locking dogs foreach sealing element—one pair will suffice to retain the sealing sleevewithin the housing so that each sealing element is located in thecentral aperture of the associated packer.

The drilling system 10 is also provided with an injection port 16 whichis located between two sealing devices 12 a, 12 b. Where the two sealingdevices 12 a, 12 b are integrated in a single housing as describedabove, the injection port 16 can, for example, extend through thehousing into the main passage of the housing between the upper and lowersealing elements of the seal sleeve assembly. Thus, fluid being injectedinto injection port 16 enters a confined annular volume 12 c between theupper and lower sealing devices 12 a, 12 b, which forms an internalcavity and part of a circulating system, once hydraulic closing pressureP_(RDD1) has been applied to the upper sealing element and P_(RDD2) tothe lower sealing element.

The injection port 16 is connected to an injection line 20 which isequipped with an injection pump 24 which is operable to draw fluid froma storage reservoir 26, and inject the fluid under pressure into theinjection port 16.

In this embodiment, the storage reservoir is divided into two volumes—anactive tank 26 a and a mixing tank 26 b. A water or oil based low solidsdrilling fluid, compatible with the drilling fluid system used in thedrilling operation, is mixed in the mixing tank 26 b. The mixing tank 26b contains a simplified and easy to access mixing system (not shown)which provides the necessary shear force to mix lubricants or otherfriction reducing additives into the base fluid, and also providingconstant agitation and the necessary shear force in the storage tanks 26a, 26 b to provide effective mixing and prevention of settled/separatedfluids. The active tank 26 a provides the sufficient volume required forthe injection circuit, and supplies the necessary feed rate of fluid tothe injection pump 24 through a single or series of charge pumps (notshown). The injection pump 24 is operable to supply the required fluidrate from the active tank 26 a and delivers it at the required injectionpressure, referred to as P_(SIC), to the circuit given the wellborepressure P_(WB) present.

Each tank 26 a, 26 b within the storage reservoir 26 is equipped with alevel sensor and alarm system 28, which transmits data representing theliquid level in each tank 26 a, 26 b to a central processing unit (CPU)30 for processing. These values are used in part to determine any volumeanomalies occurring within the circulating volume of the injectioncircuit, while ensuring that the volume of fluid in the active tank 26 aremains above the required operating level. The data analysis resultsare transmitted to the human machine interface (HMI) display 32, whichis the main user interface and control for the drilling system. It isappreciated the total system volume capacity of the tanks 26 a, 26 bwill vary, and may be determined by the space available on the offshoreinstallation where it is used.

The HMI 12 allows a user to input operational safety set points whichgovern the functioning of the system. For example, this may be upper andlower limits on pressures, temperatures, and flow rates. When these setpoints are reached, the data is processed within the CPU 11 and alarmsare triggered through the HMI 12 display. Thus, the HMI provides theuser with a central control and data monitoring point for the SIC.

The injection line 20 is fitted with a pressure relief system 34 with anoutlet connected to the active tank 26 a of the storage reservoir 26, aflow meter 36, for example, a highly accurate mass flow meter referredto as a Coriolis meter, a pressure sensor 38, a temperature sensor 40, acheck valve 42 to prevent back flow into the circuit, and an isolationvalve 44. It should be appreciated that more than one isolation valvesmay be provided. The flow meter 36, pressure sensor 38 and temperaturesensor 40, and valves 42 and 44 are all connected to the CPU 30 so thatthe flow, temperature, pressure, and valve status data may be processedwithin the CPU 30 and transmitted to the HMI display 32.

In an embodiment of the present invention, the injection line diametercan, for example, be such that large pressure losses are not incurred inthe circuit at its maximum circulating rate with a specific fluid incirculation. In an embodiment, the injection line has a 2 inch internaldiameter.

The drilling system 10 is also provided with a return port 18 locatedopposite the injection port 16, located between the upper and lowersealing devices 12 a, 12 b. A return line 22 is connected to the returnport 18, and the return line 22 and injection line 20 create a closedloop circulation system with the confined annular volume 12 c betweenthe upper and lower sealing devices 12 a, 12 b. This closed loop ishereinafter referred to as the seal integrity circuit or SIC.

The return line 22 connects the return port 18 to the storage reservoir26, and is equipped with a choke valve or back pressure valve 56 and twoalternate flow paths. The flow path depends on the operating conditionspresent, for example, if there is entrained gas within the return flowstream.

In one embodiment, the return line 22 is fitted with an isolation valve46, a pressure sensor 48, a temperature sensor 50, pressure reliefsystem 52, a flow meter 54 which, in this embodiment, is a highlyaccurate mass Coriolis meter, all of which are located upstream of theback pressure valve 56. It should be appreciated that one or moreisolation valves may be provided in the return line 22. As with theinjection line 20, the flow meter 54, pressure sensor 48, temperaturesensor 50, and valves 46 and 56 are all connected to the CPU 30 so thatthe flow, temperature, pressure, and valve status data may be processedwithin the CPU 30 and transmitted to the HMI display 32.

In an embodiment of the present invention, the return line diameter can,for example, be such that large pressure losses are not incurred in thecircuit at its maximum circulating rate with the fluid type incirculation. For example, the return line 22 may be, but is not limitedto, a 2 inch in internal diameter.

The isolation valves 44, 46 and choke valve 56 are “fail close” valvesto prevent the escape of fluid from the confined annular volume betweenthe two sealing devices 12 a, 12 b, such that pressure is maintainedwithin the circuit if a return line rupture or leak occurs.

The pressure sensors 38, 48 in the injection line 20 and return line 22thus monitor the SIC pressure P_(SIC) upstream and downstream of theconfined annular volume 12 c between the two sealing devices 12 a, 12 b.This is the measurement of the pressure contained within the confinedannular volume 12 c between the upper and lower sealing devices 12 a, 12b, the injection line 20, and the return line 22 up to the back pressurevalve 56.

In one embodiment, the drilling system 10 includes a further pressuresensor 58, hereinafter referred to as the lower annulus pressure sensor58, which is located in the annular space around the drill string 14below the lowermost sealing device 12 b, and, as such, monitors thewellbore pressure P_(WB) in the riser or wellbore annulus below thelowest sealing device 12 b. A further pressure sensor 60, hereinafterreferred to as the upper annulus pressure sensor 60, is located in theannular space around the drill string 14 above the uppermost sealingdevice 12 b. This pressure sensor 60 thus monitors the hydrostaticpressure acting downwards on the upper sealing device 12 a from theheight of the fluid column in the annulus above the sealing devices 12a, 12 b, and its value depends on the mud weight and setting depth ofthe sealing devices 12 a, 12 b within the riser. Again, these pressuresensors 58, 60 are connected to the central CPU 30 so that data signalsrepresentative of the pressure measured by each sensor 58, 60 can betransmitted to and processed by the CPU 30 and transmitted to the HMIdisplay 32.

As mentioned above, the return line 22 includes two alternate flowpaths. An emergency flow path allows the SIC return flow stream to bediverted to a mud-gas separator (MGS) 62, whilst the main flow pathallows the SIC return stream to return to the storage reservoir 26. Themain flow path comprises a main return flow line 64 which extends fromthe return line 22 downstream of the back pressure valve 56 to theactive tank 26 c of the storage reservoir 26 via a return valve 65 andsolids filtering device 66 used to process the returned fluid and removeentrained solids before it is returned to the storage reservoir 26. Theemergency flow path comprises an emergency flow line 68 which extendsfrom the return line 22 downstream of the back pressure valve 56 to theMGS 62 via an MGS inlet valve 70.

The MGS has a gas outlet 72 which vents to a safe area away from therig, and a liquid outlet 74 which is connected to the rig's conventionalfluid treatment system.

An outlet of the pressure relief system 52 in the return line 22 is alsoconnected to the MGS 62.

In an embodiment of the present invention, the injection pump 24, valves44, 46, 56, 65, and 70, pressure relief systems 34, 52, and thehydraulic control valves for closing or opening the two sealing devices12 a, 12 b can, for example, all be connected to the central CPU 11, sothat operation of these may be controlled by the CPU 30 throughprogrammable logic controllers (PLC) is as well known in the art.

The pressure relief systems 34, 52 included in the injection line 20 andreturn line 22 are configured to activate when the SIC pressureapproaches a maximum static operating pressure P_(MAX static). Asmentioned above, on the injection line 20 the relief system 34 relievesfluid pressure to the active tank 26 a, whilst in the return line 22,the pressure relief system 52 relieves pressure to the MGS 62 tomitigate any gas that may be present in the fluid stream whenP_(MAX static) is reached. The setpoint for the pressure relief systems34, 52 is a user input within the HMI 32, and the central CPU 30processes data from the pressure sensors 38 (i.e. measuring upstreampressure) and 48 (i.e. measuring downstream pressure) to determine ifthe maximum allowable static pressure P_(MAX static) of the circuit isbeing approached. The pressure relief systems 34, 52 relieve thepressure within the SIC once the safety set point is reached. Checkvalve 42 in the injection line 20 prevents reverse flow from occurringback through the injection line as the injection line pressure reliefsystem 34 relieves pressure to the active tank 26 a. The safety setpointmay be, but is not limited to, 80% to 90% of the maximum allowablecirculating pressure P_(MAX static).

A further return port (not shown) may also be provided directly abovethe uppermost sealing device 12 a. This further return port could beconnected to the main return flow line 64, the or to a further returnline which extends to the storage reservoir 26. In this case,advantageously, a further flow meter is provided to measure the rate offlow of fluid through the further return port.

A method of operating the drilling system 10 is illustrated in FIG. 2,and will be described further below.

With the drill string 14 present as described above, the injection pump24 is operated to establish an injection rate through the injection port16 and into the volume between the upper and lower sealing devices 12 a,12 b. The injected fluid therefore displaces the fluid present in theconfined annular volume 12 c between the two sealing devices 12 a, 12 b,and exits through the return port 18. The sealing devices 12 a, 12 b,are, at this stage, still open, so the fluid displaced by the injectedfluid, and then the injected fluid itself, also flows upwards anddownwards through the riser. This displaces the drilling fluid below thesealing devices to create a fluid buffer below the sealing devices 12 a,12 b. Once this displacement of drilling fluid is completed, theinjection of fluid through the injection port 16 is momentarily stopped,whilst the sealing devices 12 a, 12 b are closed by energizing bothsealing elements of the seal sleeve so that they enter into sealingengagement with the drill string 14.

Injection of fluid through the injection port 16 is then resumed. Atthis stage, substantially all of the injected fluid exits the confinedannular volume 12 c between the two sealing devices 12 a, 12 b via thereturn port 18, and so the flow rate through the injection port 16(measured using flow meter 36) is substantially equal to the flow ratethrough the return port 18 (measured using flow meter 54). The closingpressure of the lowest sealing device 12 b is then reduced until areduction in the return flow rate is detected, indicating there is fluidflowing across the lower sealing face

The same may be performed for the upper sealing device 12 a, with afurther decrease in the return line rate indicating that there is fluidflowing across the upper sealing face. In this case, where there is afurther return port provided above the upper sealing device 12 a, thisfluid is returned to the storage reservoir via the further return port.Alternatively, if no such further return port is provided, because theriser volume above the sealing devices 12 a, 12 b will be full of fluidanyway, this fluid returns to rig's fluid treatment system via theconventional diverter system.

The injected fluid thus provides lubrication and cooling within thesealing faces of the sealing devices to minimize heat generation,friction, and wear rates of the sealing elements. Furthermore, the fluidcreates a fluid buffer zone directly beneath the lowest sealing devicewhich displaces the drilling fluid, drilling solids, and gasified fluidaway from the confined annular volume 12 c such that the likelihood ofinvasion of gas and fluid upwards through the sealing faces of thesealing devices 12 a, 12 b is reduced. As such, the injected fluid can,for example, be a fluid with low friction coefficients and relativelyhigh heat transfer coefficients. Additives may be added to the fluid tofurther alter friction and heat transfer properties.

At this point, the MGS inlet valve 70 is closed, and the return flowvalve 65 is open, so the return flow stream flows along the main returnflow line 64 and is diverted through the solids filtering device 66 andback to the storage reservoir 26, maintaining the SIC circulatingvolume. The flow of injected fluid across the sealing faces of thesealing devices 12 a, 12 b provides that lubrication of the sealingdevices 12 a, 12 b is achieved and so drilling can commence, with anychanges to the injection and return rates and pressures signifyingchanges in the integrity of the seal sleeve. Monitoring the temperatureof the return stream will indicate the degree of friction present withthe associated closing pressures, wellbore pressure, and drillpipe speedthrough the seal sleeve. Automatic adjustment of the closing pressureson the sealing devices can be used to achieve an optimal fluid injectionrate across the sealing faces which results in a maximum reduction infriction, heat generation, and wear rate for any wellbore pressure thatis present.

The SIC operating pressure may also be automatically maintained at asafe level above the existing wellbore pressure, whilst ensuring apositive differential pressure exists across the sealing devices 12 a,12 b, and alarms raised when SIC pressure values decrease to user inputset points within the CPU 30. A positive differential pressure assistsin maintaining seal integrity when larger diameter tubulars ordiametrical changes pass through the seal sleeve assembly. Furthermore,over pressuring of the SIC is prevented through the pressure reliefvalve systems 34, 52 in both the injection line 20 and return line 22.

The desired operating SIC pressure P_(SIC) is defined by the largestmagnitude of pressure the sealing devices 12 a, 12 b are exposed to.Hence, the greater of the wellbore pressure P_(WB) and the upper riserannulus hydrostatic pressure P_(HP) is determined, and the 250 to 500psi positive differential is applied to the greater of these twopressures. The hydrostatic pressure P_(HP) effects becomes moreprominent at deeper subsea setting depths for the RDD, but at shallow orsurface set depths the largest pressure differential is always createdby the wellbore pressure P_(WB) across the lower sealing device 12 b.

The positive differential ΔP_(LOWER) across the lower sealing device 12b is achieved through the continuous data analysis within the algorithmsof the CPU 30 from pressure PT1 measured by the injection line pressuresensor 38, the pressure PT4 measured by the return line pressure sensor48 and the pressure PT2 measured by the lower annulus pressure sensor58, and is represented by the relationships

PT4−PT2=ΔP _(LOWER)

PT1−PT2=ΔP _(LOWER)

Or alternately

P _(SIC) −P _(WB) =ΔP _(LOWER)

Where the pressure values measured by the injection pressure sensor 38and return line pressure sensor 48 are the SIC circulating pressureP_(SIC) upstream and downstream of the confined annular volume 12 c. Therelationships described herein represent the same parameter(ΔP_(LOWER)), with PT4 and PT1 providing qualitative data checks onP_(SIC) through an upstream PT1 and downstream PT4 pressure measurement.ΔP_(LOWER) should be a positive value, representing a positive pressuredifferential ΔP_(LOWER) across the lower sealing element when thesealing devices 12 a, 12 b are installed near the surface of a marineriser or on top of a land based BOP. However, at deeper subsea settingdepths in a marine riser these conditions change, which is discussedlater. A positive differential pressure ΔP_(LOWER) may reduce thelikelihood of the ingress of wellbore fluid from the annulus below thesealing devices 12 a, 12 b at the current wellbore pressure P_(WB)through the lower sealing device 12 b, which is undesired as it maycontain solids and entrained gas.

Furthermore, by applying the SIC pressure P_(SIC) through the confinedannular volume 12 c, the magnitude of the differential pressureΔP_(LOWER) across the lowest sealing device 12 b is decreased. Lowerwear rates in the sealing element of any BOP or pressure containmentdevice are observed at lower wellbore pressures P_(WB). Without applyingthe SIC pressure P_(SIC), the largest differential pressure ΔP_(LOWER)exists within the sealing face in the lower area of the lowermostsealing device 12 b and results in a tendency to wear at a higher rateduring drill string 14 movement. By increasing P_(SIC) within a range of250 to 500 psi above the wellbore pressure P_(WB), the differentialpressure ΔP_(LOWER) across the lower sealing device 12 b and within thelower area of the seal is greatly decreased. Thus the operationallongevity of the seal sleeve assembly may be enhanced.

For example, if the wellbore pressure P_(WB) is 750 psi, the SICpressure P_(SIC) is increased to 1,000 psi, and both injection pressuresensor 38 and return pressure sensor 48 measure a circuit pressure of1,000 psi, the following relationships hold true

PT4−PT2=1000−750=250 psi=ΔP _(LOWER)

PT1−PT2=1000−750=250 psi=ΔP _(LOWER)

P _(SIC) −P _(WB)=1000−750=250 psi=ΔP _(LOWER)

Hence, a positive differential pressure ΔP_(LOWER) of 250 psi existsacross the lower sealing device 12 b.

It will be appreciated, of course, that these values are used by way ofexample only, and the SIC pressure P_(SIC) may circulate at any givenpressure above the wellbore pressure P_(WB), as long as a positivepressure differential ΔP_(LOWER) results across the lower sealing device12 b.

It is also desired to maintain a positive differential pressureΔP_(UPPER) across the upper sealing device 12 a. This is to prevent theingress of drilling fluid from the column of drilling fluid in the riserannulus above the upper sealing device 12 a into the SIC. With thesealing devices 12 a, 12 b installed close to surface in the riser or ontop of a land based BOP, this is not an issue as a short column of fluidabove results in a very minimal acting hydrostatic pressure P_(HP) giventhese conditions. A positive differential pressure ΔP_(UPPER) alwaysresults as the largest magnitude of pressure is the wellbore pressureP_(WB) given these conditions, and the SIC pressure P_(SIC) adjusts tomitigate this pressure P_(WB). However, as the subsea setting depthdeepens, the hydrostatic pressure P_(HP) becomes more pronounced.

The positive differential ΔP_(UPPER) across the upper sealing element 4Ais achieved through the continuous data analysis within the algorithmsof the CPU 30 using the pressure PT1 measured by the injection linepressure sensor 38, the pressure PT4 measured by the return linepressure sensor 48 and the pressure PT3 measured by the upper annuluspressure sensor 60, and is represented by the relationships:

PT4−PT3=ΔP _(UPPER)

PT1−PT3=ΔP _(UPPER)

Or alternately

P _(SIC) −P _(HP) =ΔP _(UPPER)

Where the pressure values measured by the injection pressure sensor 38and the return pressure sensor 48 are the SIC circulating pressureP_(SIC) upstream and downstream of the confined annular volume 12 c. Therelationships, described herein, represent the same parameter(ΔP_(UPPER)), with PT4 and PT1 providing qualitative data checks onP_(SIC) through an upstream PT1 and downstream PT4 pressure measurement.ΔP_(UPPER) should be a positive value, representing a positive pressuredifferential ΔP_(UPPER) across the upper sealing device 12 a when thesealing devices 12 a, 12 b, which is always the case, is installed nearor at the surface.

For example, with the setting depth of the sealing devices 12 a, 12 bset at 300 ft and a drilling fluid density of 10 ppg, the resultanthydrostatic pressure P_(HP) acting on the upper sealing device 12 a is:

P _(HP)=Height×Mud Weight×0.052

P _(HP)=300 ft×10 ppg×0.052=156 psi

If the hydrostatic pressure P_(HP) is 156 psi and the current wellborepressure P_(WB) is 500 psi, the wellbore pressure P_(WB) is determinedto be the highest degree of pressure present, thus creating the largestnegative differential pressure ΔP_(LOWER) across the lower sealingdevice 12 a. Thus a negative differential pressure ΔP_(UPPER) of 156 psiexists across the upper sealing device 12 and a negative differentialpressure ΔP_(LOWER) of 500 psi exists across the lower sealing device 12b in absence of SIC pressure P_(SIC). Therefore, the SIC pressureP_(SIC) is increased to 750 psi to decrease the differential pressureΔP_(LOWER) across the lower sealing device 12 a and impose a 250 psipositive pressure differential ΔP_(LOWER) across the lower sealingdevice 12 b.

The following relationships for the upper sealing device 12 a hold trueassuming PT4 and PT1 are measuring 750 psi of SIC pressure:

PT4−PT3=750−156=594 psi=ΔP _(UPPER)

PT1−PT3=750−156=594 psi=ΔP _(UPPER)

P _(SIC) −P _(HP)=750−156=594 psi=ΔP _(UPPER)

Thus, a positive pressure differential ΔP_(UPPER) of 594 psi is alsocreated across the upper sealing element under these conditions.

However, if the subsea setting depth is increased to 2,000 ft with a 10ppg drilling fluid density, the following hydrostatic pressure results:

2,000 ft×10 ppg×0.052=1040 psi

If the current wellbore pressure P_(WB) is 750 psi the algorithms withinthe CPU 30 determine the hydrostatic pressure P_(HP) is the highestdegree of pressure present, thus creating the largest negativedifferential pressure ΔP_(UPPER) across the upper sealing device 12 a.Thus a negative differential pressure ΔP_(UPPER) of 1040 psi existsacross the upper sealing device 12 a and a negative differentialpressure ΔP_(LOWER) of 750 psi exists across the lower sealing device 12b in the absence of SIC pressure P_(SIC). Therefore, the SIC pressureP_(SIC) is increased to 1,290 psi to decrease the differential pressureΔP_(UPPER) across the upper sealing device 12 a and impose a 250 psipositive pressure differential ΔP_(UPPER) across the upper sealingdevice 12 a. Subsequently, a positive differential pressure ΔP_(LOWER)of 540 psi is produced across the lower sealing device 12 b.

It will be appreciated that the SIC pressure will be determined by thespeed of operation of the injection pump 24, the degree of restrictionof fluid flow along the return line 22 provided by back pressure valve56, and the closing pressures P_(RDD1) and P_(RDD2) applied to the twosealing devices 12 a, 12 b (as this determines the rate of leakage offluid out of the confined annular volume 12 c). As mentioned above,however, automatic adjustment of the closing pressures on the sealingdevices 12 a, 12 b can be used to achieve an optimal fluid injectionrate across the sealing faces which results in a maximum reduction infriction, heat generation, and wear rate for any wellbore pressure thatis present.

It will therefore be appreciated that, through the process ofcontrolling P_(SIC) to adjust the upper and lower differential pressuresΔP_(UPPER), ΔP_(LOWER), the leak rate through the sealing faces of theupper and lower sealing devices 12 a, 12 b is also affected. The flowpaths become more restricted through the sealing face if the closingpressures P_(RDD1), P_(RDD2) are increased and/or the leak rate throughthe sealing faces increases if the backpressure valve 56 is closedfurther. The hydraulic closing pressures P_(RDD1), P_(RDD2) ultimatelyaffect the differential pressures ΔP_(LOWER), ΔP_(UPPER) produced acrossthe sealing devices 12 a, 12 b in addition to the leak rate/lubricatingrate occurring across the sealing faces. Thus, these are interrelatedfunctions performed within the CPU 36 between the SIC and the hydrauliccontrols of the sealing devices 12 a, 12 b to optimize the leak rate andclosing pressures P_(RDD1), P_(RDD2) while maintaining the pressureintegrity of the sealing devices 12 a, 12 b. The adjustment of thehydraulic closing pressures P_(RDD1) and P_(RDD2) in relation to theleak rate, the differential pressures ΔP_(UPPER) and ΔP_(LOWER), andmaintaining an effective seal on the drill string 14 is referred to asthe Activation Pressure Bios (APB). The APB ultimately controls the leakrate through the sealing faces of the seal sleeve assembly for optimallubrication and cooling of the system.

The leak rate and fluid buffer methodology utilizes the injection pump24, the injection and return flow meters 36, 54, and the closingpressures P_(RDD1) P_(RDD2) of the upper and lower sealing devices 12 a,12 b. It involves the hydraulic control system of the sealing devices 12a, 12 b working in parallel with the SIC for adjusting the closingpressures and leak rates to achieve maximum longevity of the seal sleeveassembly.

The data analysis carried out by the CPU 30 using data streams from thepressure sensors 38, 48, 58, 60, temperature sensors 40, 50, and flowmeters 36, 54 can be used to automate the operation of the injectionpump 24, valves 44, 46, 56, 65, and 70, pressure relief systems 34, 52,and the hydraulic closing pressures P_(RDD1), P_(RDD2) throughprogrammable logic controllers (PLC) well known in the art.

Referring now to FIG. 2, this shows a flow diagram illustrating theprocess logic within the CPU 30 of the drilling system, which governsthe pressure feedback loop for the automated adjustment of the SICpressure.

The algorithms within the CPU 30 continuously monitor and analyze thepressure data for wellbore pressure P_(WB), the SIC circulating pressureP_(SIC), the hydrostatic pressure above the upper sealing elementP_(HP), the hydraulic closing pressure of the upper sealing deviceP_(RDD1), and the hydraulic closing pressure of the lower sealing deviceP_(RDD2) 20 (step 80 in FIG. 2).

If the SIC pressure P_(SIC) is at or approaching a maximum circulatingpressure P_(MAX) an emergency procedure is followed (82). This will bedescribed further below. Otherwise, the algorithms within the CPU 36evaluates the wellbore pressure P_(WB) and hydrostatic pressure P_(HP)acting on the sealing elements, and determines which is the greater ofthe two pressures (step 84).

If it is determined the greater of the two pressures is the wellborepressure P_(WB), the lower pressure differential ΔP_(LOWER) analysis isperformed on the lower sealing element, examining the pressure data forthe current wellbore pressure P_(WB) and the circulating pressure of theSIC P_(SIC) (step 86). If the SIC pressure P_(SIC) is greater than thecurrent wellbore pressure P_(WB) (step 86), the algorithms identify thisas a positive lower pressure differential ΔP_(LOWER), and then analyzethe magnitude of the resultant positive pressure differential ΔP_(LOWER)(step 88). If the positive pressure differential is between 250 to 500psi, the algorithms deem this safe operating conditions and drilling ortripping operations continue unimpeded (step 90).

If the lower differential pressure ΔP_(LOWER) analysis proves to be lessthan the existing wellbore pressure P_(WB) (step 86) the algorithmsidentify this as a negative lower pressure differential ΔP_(LOWER). Theback pressure valve 56 can be further closed or the hydraulic closingpressure for the lower sealing device P_(RDD2) increased to increase thedifferential pressure ΔP_(LOWER) across the lower sealing device 12 b(step 92). Increasing the lower element closing pressure P_(LOWER) isconsidered the APB, described herein, and restricts the lubrication rateacross the lower sealing device 12 b which increases the SIC pressureP_(SIC) and ultimately increases the lower differential pressureΔP_(LOWER).

Once the back pressure valve 56 or the lower sealing device closingpressure P_(RDD2) has been adjusted, the algorithms within the CPU 30examine the resultant lower differential pressure ΔP_(LOWER) (94). If ithas increased, the pressure feedback loop is repeated from step 80. Ifthe lower differential pressure ΔP_(LOWER) has not increased, a systemtroubleshooting procedure is implemented (step 96). The backpressurevalve 56 or the lower sealing device closing pressure P_(RDD2) may befurther adjusted to observe the effects on the lower pressuredifferential ΔP_(LOWER). Once a positive lower differential pressureΔP_(LOWER) has been achieved, the pressure feedback loop is repeatedfrom step 80. If the lower differential pressure ΔP_(LOWER) is still notchanging, it may be necessary to stop operations until the problem isresolved.

If it is determined in step 84 that the greater of the two pressures isthe hydrostatic pressure P_(HP), the upper pressure differentialΔP_(UPPER) analysis is performed (step 98). An identical sequence occursfor the upper differential pressure ΔP_(UPPER) analysis, with thealgorithms examining the current hydrostatic pressure P_(HP) exerted onthe upper sealing device 12 a and evaluating if the SIC circulatingpressure P_(SIC) is greater than this value.

If the SIC pressure P_(SIC) is greater than the hydrostatic pressureP_(HP), the algorithms identify this as a positive upper pressuredifferential ΔP_(UPPER) and then calculates and analyses the magnitudeof this value (step 100). If the positive pressure differential isbetween 250 to 500 psi, the algorithms deem this as safe operatingconditions and drilling or tripping operations continue unimpeded (step90).

If the upper differential pressure ΔP_(UPPER) analysis (98) proves to beless than the hydrostatic pressure P_(HP), the algorithms identify thisas a negative upper pressure differential ΔP_(UPPER). The back pressurevalve BPV1 can be further closed or the hydraulic closing pressure forthe upper sealing element P_(RDD1) increased to increase thedifferential pressure ΔP_(UPPER) across the upper sealing device 12 a(step 92). Increasing the upper element closing pressure P_(UPPER) isconsidered the APB, described herein, and restricts the lubrication rateacross the upper sealing face which increases the SIC pressure P_(SIC)and ultimately increases the upper differential pressure ΔP_(UPPER).

Once the backpressure valve 56 or the upper sealing device closingpressure P_(RDD1) has been adjusted, the algorithms of the CPU 30re-examine the upper differential pressure ΔP_(UPPER) (94). If it hasincreased, the pressure feedback loop is repeated from step 80. If theupper differential pressure ΔP_(UPPER) has not increased, atroubleshooting procedure is implemented (96). The backpressure valve 56or the upper element hydraulic closing pressure P_(RDD1) may be furtheradjusted to observe the effects on the upper pressure differentialΔP_(UPPER). Once a positive upper differential pressure ΔP_(UPPER) hasbeen achieved, the pressure feedback loop is repeated from step 80. Ifthe upper differential pressure ΔP_(UPPER) is still not changing, it maybe necessary to stop operations until the problem is resolved.

The algorithms within the CPU 30 also detect when the maximumcirculating pressure and the maximum static pressure of the SIC isapproached through user input safety set points. In this embodiment, themaximum allowable circulating pressure P_(MIX circ) is 2,000 psi and themaximum allowable static pressure is 3,000 psi, however, it isappreciated these maximum allowable pressures may vary from system tosystem. When pressures approach the maximum allowable circulatingpressure P_(MAX circ) and beyond, it is considered emergency operatingconditions for the SIC.

As the CPU 30 processes the data from injection and return pressuresensors 38, 48 it determines if the safety set point for the maximumallowable circulating pressure P_(MAX circ) is being approached (step82). When this condition occurs, the system automatically stops theinjection pump 24 (step 102) and maintains the SIC pressure P_(SIC) atits last recorded value using the back pressure valve 56 and/or thehydraulic closing pressures P_(RDD1) and P_(RDD2) for the upper andlower sealing devices 12 a, 12 b, and pressure data from the injectionpressure transducer 38 and return pressure transducer 48 (step 104)—thisprevents the circulating pressure capacity P_(MAX circ) of the SIC frombeing exceeded. The safety setpoint may be, but is not limited to, 80%to 90% of the maximum allowable circulating pressure ratingP_(MAX circ).

If the pressure P_(SIC) starts returning to within its safe operatingrange, the injection pump 24 is restarted, and normal operations resume(step 106).

On the other hand, if P_(SIC) continues to increase so that the maximumallowable circulating pressure P_(MAX circ) is reached, all movement ofthe drill string 14 through the sealing devices 12 a, 12 b ceases, andtherefore current operations cease. At this stage, the main priority ofthe SIC is to maintain the seal integrity of the upper and lower sealingdevices 12 a, 12 b, and to continue to provide a positive differentialpressure across a single or both sealing devices 12 a, 12 b. Thehydraulic pressure controls apply the optimal closing pressures P_(RDD1)P_(RDD2) on the upper sealing device 12 a and lower sealing device 12 bduring this procedure.

The CPU 30 continues to monitor the wellbore pressure P_(WB) and/or theSIC pressure P_(SIC) to determine if they are continuing to increase orstarting to decrease to a safe operating pressure range. Subsequently,if it is then determined that the SIC pressure P_(SIC) is approachingthe maximum static pressure capacity of the system P_(MAX static) 33,the pressure relief systems 34, 52 operate to vent fluid to the MGS 62and the active tank 26 a of the system (step 110). Typically, the CPU 30is programmed to activate the pressure relief systems 34, 52 if P_(SIC)reaches 80% to 90% of the maximum static pressure P_(MAX static). Thealgorithms within the CPU 30 continue to analyze the pressure dataduring such a pressure relief event and adjust the hydraulic closingpressures P_(RDD1) and P_(RDD2) accordingly to maintain the pressureintegrity of the seal sleeve assembly during these high pressureconditions.

Once the SIC pressure P_(SIC) decreases back to within its safeoperating range (i.e. less than P_(MAX circ)) the injection pumpautomatically starts and circulation recommences. At this point, the SICreturns to normal operating conditions.

When gas is detected in the returning fluid, this is also considered anemergency operating condition and flow is diverted to the MGS 62 todegas the fluid and remove solids from the return stream beforereturning it to the rig fluid treatment system where it becomes part ofthe rig's active circulating system.

The presence of gas is detected using the flow meter 54 in the returnline. As this is a mass flow meter such as a Coriolis meter, it does notmeasure the volume per unit time passing through the device (i.e. thevolumetric flow rate), but measures the mass per unit time flowingthrough the device (the mass flow rate). Volumetric flow rate is themass flow rate divided by the density. The density of the fluid maychange with temperature, pressure, or composition, for example, with gasentrained within the SIC fluid. When gas is present in the system, thereturning fluid density decreases from the original base fluid densityand this is detected by the return line flow meter 54 as a change inmass flow rate. A change in mass flow rate could, of course, be theresult of a change in fluid density rather than a change in returnvolume flow rate (which could, for example, be occurring due toincreased leak rate across one of the seals. As such, the Coriolis metermeasures actual density, in addition to temperature and flow rate. TheCoriolis effect measured by the meter changes with changes in density,and thus it accurately detects density changes with a gas versus aliquid. Algorithms built into the central CPU 30 identify a change indensity versus a change in flow rate, which would then trigger a furtheremergency procedure. When gas is detected in the return stream, the CPU30 signals an alarm signal to the HMI 32, automatically opens the MGSinlet valve 70 and then closes the main return line valve 65 to divertthe returning fluid to the MGS 62 for degassing and phase separation.All separated gas is vented to a safe area away from the rig, with thedegassed fluid and/or solids diverted to the rig's fluid treatmentsystem. The returned degassed fluid from the MGS 62 is continually addedto the rig's active volume until gas is completely absent from thereturn stream. This is determined using the output of the return lineflow meter 54, and when this indicates that the density of the returnflow stream has returned to the density value of the injected fluid, thereturn line valve 65 is opened and the MGS inlet valve 70 closed again.

When used in this specification and claims, the terms “comprises” and“comprising” and variations thereof mean that the specified features,steps or integers are included. The terms are not to be interpreted toexclude the presence of other features, steps or components.

The features disclosed in the foregoing description, or the followingclaims, or the accompanying drawings, expressed in their specific formsor in terms of a means for performing the disclosed function, or amethod or process for attaining the disclosed result, as appropriate,may, separately, or in any combination of such features, be utilized forrealizing the present invention in diverse forms thereof. Referenceshould also be had to the appended claims.

What is claimed is: 1-35. (canceled)
 36. A method of operating adrilling system for drilling a subterranean bore hole, the drillingsystem comprising: a drill string configured to rotate during adrilling; and a first sealing device configured to provide asubstantially fluid tight seal around the drill string while the drillstring is rotating during the drilling, the method comprising: injectinga fluid into an annular volume around the drill string directly abovethe first sealing device; and controlling a first fluid pressure in theannular volume around the drill string above the first sealing device sothat the first fluid pressure is greater than a second fluid pressure inthe annular volume around the drill string directly below the firstsealing device.
 37. The method as recited in claim 36, wherein, thedrilling system further comprises a second sealing device arranged belowthe first sealing device, the second sealing device being configured toprovide a substantially fluid tight seal around the drill string whilethe drill string is rotating during the drilling, the injecting stepincludes injecting the fluid into the annular volume around the drillstring between the first sealing device and the second sealing device,and the controlling step includes controlling a third fluid pressure inthe annular volume around the drill string between the first sealingdevice and the second sealing device so that the third fluid pressure isgreater than the second fluid pressure in the annular volume around thedrill string directly below the second sealing device.
 38. The method asrecited in claim 37, wherein the controlling step includes controllingthe third fluid pressure in the annular volume around the drill stringbetween the first sealing device and the second sealing device so thatthe third fluid pressure is greater than the first fluid pressure in theannular volume around the drill string directly above the first sealingdevice.
 39. The method as recited in claim 37, wherein, the drillingsystem further comprises: a fluid reservoir; an injection pumpconfigured to pump the fluid from the fluid reservoir into the annularvolume around the drill string directly above the first sealing device,or, where the first sealing device and the second sealing device areprovided, into the annular volume around the drill string between thefirst sealing device and the second sealing device; and an injectionline configured to connect the annular volume around the drill stringdirectly above the first sealing device, or, where the first sealingdevice and the second sealing device are provided, the annular volumearound the drill string between the first sealing device and the secondsealing device, with the injection pump.
 40. The method as recited inclaim 39, wherein the drilling system further comprises: a return lineconfigured to connect the annular volume around the drill stringdirectly above the first sealing device, or, where the first sealingdevice and the second sealing device are provided, the annular volumearound the drill string between the first sealing device and the secondsealing device, with the fluid reservoir; and a back pressure valvearranged in the return line, the back pressure valve being configured tosubstantially restrict a flow of the fluid along the return line, themethod further comprising: controlling the first fluid pressure in theannular volume around the drill string directly above the first sealingdevice, or, where the first sealing device and the second sealing deviceare provided, the annular volume around the drill string between thefirst sealing device and the second sealing device, by controlling theback pressure valve to vary an extent to which the back pressure valverestricts the flow of the fluid along the return line.
 41. The method asrecited in claim 40, wherein the drilling system further comprises: areturn pressure sensor configured to measure a return line fluidpressure in the return line, the return pressure sensor being arrangedupstream of the back pressure valve.
 42. The method as recited in claim40, wherein the drilling system further comprises: a back pressure valvearranged in the return line, the back pressure valve being configured tosubstantially restrict a flow of the fluid along the return line. 43.The method as recited in claim 42, wherein, the drilling system furthercomprises a pressure sensor configured to measure a pressure, thepressure sensor being arranged in at least one of the injection line andthe return line, and the method further comprises: using the pressuremeasured by the pressure sensor to control the first fluid pressure inthe annular volume around the drill string directly above the firstsealing device, or, where the first sealing device and the secondsealing device are provided, using the pressure measured by the pressuresensor to control the annular volume around the drill string between thefirst sealing device and the second sealing device.
 44. The method asrecited in claim 40, wherein the drilling system further comprises: aninjection pressure sensor configured to measure an injection line fluidpressure in the injection line.
 45. The method as recited in claim 40,wherein the first sealing device, or, where the first sealing device andthe second sealing device are provided, each of the first sealing deviceand the second sealing device, is configured to exert a sealing pressurewhich is variable on the drill string when operated to seal against thedrill string.
 46. The method as recited in claim 45, wherein the methodfurther comprises: varying the sealing pressure exerted by the firstsealing device, or, where the first sealing device and the secondsealing device are provided, varying the sealing pressure exerted by thefirst sealing device and the second sealing device, on the drill stringto provide a leakage of an injected fluid between the respective sealingdevice and the drill string at a desired rate.
 47. The method as recitedin claim 46, wherein the method further comprises: controlling the firstfluid pressure in the annular volume around the drill string directlyabove the first sealing device by controlling the sealing pressure ofthe first sealing device, or, where the first sealing device and thesecond sealing device are provided, controlling the annular volumearound the drill string between the first sealing device and the secondsealing device by controlling the sealing pressure of each of the firstsealing device and the second sealing device.
 48. The method as recitedin claim 40, wherein the drilling system further comprises: a returnline flow meter arranged in the return line upstream of the backpressure valve; and an injection flow meter arranged in the injectionline, and the method further comprises: monitoring an inflow rate offlow of the fluid into the annular volume around the drill stringdirectly above the first sealing device, or, where the first sealingdevice and the second sealing device is provided, the annular volumearound the drill string between the first sealing device and the secondsealing device, monitoring an outflow rate of flow of the fluid out ofthe annular volume around the drill string directly above the firstsealing device, or, where the first sealing device and the secondsealing device is provided, the annular volume around the drill stringbetween the first sealing devices and the second sealing device;comparing the inflow rate of flow and the outflow rate of flow, andusing the comparison to detect a loss of sealing integrity of the firstsealing device, or, where the first sealing device and the secondsealing device is provided, in at least one of the first sealing deviceand the second sealing device.
 49. The method as recited in claim 48,wherein the drilling system further comprises: a return pressure sensorconfigured to measure the fluid pressure in the return line, wherein,the injection flow meter and the return line flow meter are each a massflow meter, and the method further comprises: comparing the inflow rateof flow and the outflow rate of flow, and using the comparison to detectan influx of gas in the injected fluid.
 50. The method as recited inclaim 49, wherein the drilling system further comprises: a mud gasseparator, and the method further comprises: directing fluid from thereturn line to the mud gas separator if the influx of gas is detected inthe injected fluid; and returning a degasified liquid from the mud gasseparator to the fluid reservoir.
 51. The method as recited in claim 49,wherein, the return line includes a main returns flow line which extendsdirectly to the fluid reservoir, an emergency returns flow line whichextends to the mud gas separator, and a valve assembly configured tocontrol a flow of fluid along the main returns flow line and theemergency returns flow line, and the method further comprises: operatingthe valve assembly to close the main returns flow line and to open theemergency returns flow line if the influx of gas is detected in theinjected fluid.
 52. The method as recited in claim 39, wherein, thedrilling system is configured to automatically switch off the injectionpump if the first fluid pressure in the annular volume around the drillstring directly above the first sealing device, or, where the firstsealing device and the second sealing device is provided, the annularvolume around the drill string between the first sealing device and thesecond sealing device, exceeds a predetermined level.
 53. The method asrecited in claim 52, wherein the method further comprises: adjusting thesealing pressure of the first sealing device to reduce the first fluidpressure in the annular volume around the drill string directly abovethe first sealing device, or, where the first sealing device and thesecond sealing device is provided, the annular volume around the drillstring between the first sealing device and the second sealing device,to below the predetermined level.
 54. A tangible computer readablemedium comprising instructions installed thereon which, when executed bya processing device, cause the processing device to perform a method ofoperating a drilling system for drilling a subterranean bore hole, thedrilling system comprising: a drill string configured to rotate during adrilling; and a sealing device configured to provide a substantiallyfluid tight seal around the drill string while the drill string isrotating during drilling, the method comprising: injecting a fluid intoan annular volume around the drill string directly above the sealingdevice; and controlling a first fluid pressure in the annular volumearound the drill string above the first sealing device so that the firstpressure is greater than a second fluid pressure in the annular volumearound the drill string directly below the first sealing device.
 55. Thetangible computer readable medium as recited in claim 33, wherein themethod further comprises: varying a sealing pressure exerted by thesealing device on the drill string to establish a leakage of the fluidbetween the sealing device and the drill string at a desired rate.